Publication number | US20030094040 A1 |

Publication type | Application |

Application number | US 10/254,310 |

Publication date | May 22, 2003 |

Filing date | Sep 25, 2002 |

Priority date | Sep 28, 2001 |

Also published as | US7059179 |

Publication number | 10254310, 254310, US 2003/0094040 A1, US 2003/094040 A1, US 20030094040 A1, US 20030094040A1, US 2003094040 A1, US 2003094040A1, US-A1-20030094040, US-A1-2003094040, US2003/0094040A1, US2003/094040A1, US20030094040 A1, US20030094040A1, US2003094040 A1, US2003094040A1 |

Inventors | Mark Proett, Wilson Chin |

Original Assignee | Halliburton Energy Services, Inc. |

Export Citation | BiBTeX, EndNote, RefMan |

Patent Citations (14), Referenced by (47), Classifications (7), Legal Events (3) | |

External Links: USPTO, USPTO Assignment, Espacenet | |

US 20030094040 A1

Abstract

The specification discloses a downhole tool that determines hydraulic permeability of a downhole formation taking into account one or both of the dip angle of the borehole relative to the formation, and damage to the borehole wall and invasion of borehole fluid—collectively referred to as skin.

Claims(31)

coupling a first probe to the earth formation;

coupling a second probe to the earth formation;

inducing a fluid flow from the formation into the first probe;

measuring a pressure response at the first probe caused by the fluid flow;

measuring a pressure response at the second probe caused by the fluid flow; and

determining the effect skin of the formation has on a measured hydraulic permeability of the formation, the determination based on the pressure responses measured at the first and second probes.

where ΔP_{p }is the modeled pressure response the first probe, S_{d }is a dimensionless skin constant, k_{f }is the spherical permeability, μ is a formation fluid viscosity, Q_{0 }is the rate of fluid flow from the formation into the first probe, τ_{s }is a geometric shape factor for the first probe, r_{p }is the first probe radius, and p_{ds }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the earth formation, t_{d }is dimensionless time, y_{n }is one of:

and where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

where ΔP_{Z }is the modeled pressure response at the second probe, τ_{v }is a geometric shape factor for the second probe, r_{v }is a physical spacing between first and second probe, k_{r }is the horizontal permeability, r_{dv }is a dimensionless spacing between the first and second probe and p_{d }is a predicted transient response given substantially by the equation:

a tool body;

a first probe coupled to the tool body, the first probe adapted to be fluidly coupled to a borehole wall, the first probe having a first pressure transducer coupled thereto;

a second probe coupled to the tool body and vertically displaced from the first probe, the second probe adapted to be fluidly coupled to the borehole wall, and the second probe having a second pressure transducer coupled thereto;

a pump coupled to the first probe;

a computer coupled to the first and second pressure probes, and wherein the computer is adapted to read pressures responses sensed at the first and second pressure transducers to determine hydraulic permeability anisotropy and skin of a formation taking into account a dip angle between the borehole and the formation.

where ΔP_{p }is the modeled pressure reaction the first probe through which a draw-down test is performed, S_{d }is a dimensionless skin constant, k_{f }is the spherical permeability, μ is a formation fluid viscosity, Q_{0 }is the rate of fluid flow from the formation into the first probe, τ_{s }is a geometric shape factor for the first probe, r_{p }is first probe radius, p_{ds }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the formation, t_{d }is dimensionless time, y_{n }is one of:

and where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

where ΔP_{Z }is the modeled pressure response at the second probe, τ_{v }is a geometric shape factor for the second probe, r_{v }is a distance between the first probe and the second probe, k_{r }is the horizontal permeability, λ is the hydraulic permeability anisotropy, θ is the angle of the formation relative to an axis of the borehole, r_{dv }is a dimensionless distance between the first probe and the second probe and p_{d }is a predicted transient response given substantially by the equation:

performing a draw-down test on an anisotropic earth formation traversing a borehole;

detecting formation pressure reactions associated with the draw-down test at a first probe and a second probe;

determining hydraulic permeability anisotropy of the earth formation using the formation pressure reactions and taking into account a dip angle of the earth formation.

where ΔP_{p }is a modeled pressure response the first probe, k_{f }is a spherical permeability, μ is a formation fluid viscosity, Q_{0 }is a rate of fluid flow from the formation into the first probe during the draw-down test, τ_{s }is a geometric shape factor for the first probe, r_{p }is the first probe radius, and p_{d }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the earth formation, t_{d }is dimensionless time, r_{d }is equal to 1, β_{1 }is given substantially by:

and where β_{2 }is given substantially by:

where ΔP_{Z }is the modeled pressure response at the second probe, τ_{v }is a geometric shape factor for the second probe, r_{v }is radius correction factor for the second probe, k_{r }is the horizontal permeability, r_{dv }is a dimensionless spacing between the first and second probe and p_{dv }is a predicted transient response given substantially by the equation:

where Y_{n }is given by:

a tool body adapted to be suspended in a borehole by way of a cable;

a source probe coupled to the tool body, the source probe adapted to be fluidly coupled to the borehole wall;

a pump coupled to the source probe, the pump adapted to displace fluid through the source probe while the source probe is coupled to the borehole wall;

a first pressure transducer coupled to the source probe, the first pressure transducer adapted to sense a pressure response of the formation caused by the displacing of fluid through the source probe; and

a computer coupled to the pump and first pressure transducer through the cable, wherein the computer selective controls the pump, and records the pressure response sensed by the first pressure transducer, and wherein the computer is adapted to determine spherical permeability and skin of the formation adjacent to the borehole wall based on the pressure response sensed.

where ΔP_{p }is the modeled pressure response, S_{d }is a dimensionless skin constant, k_{f }is the spherical permeability, μ is a formation fluid viscosity, Q_{0 }is the rate of displaced from the formation into the source probe, τ_{s }is a geometric shape factor for the source probe, r_{p }is the source probe radius, p_{ds }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the formation, td is dimensionless time, y_{n }is one of:

and where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

a vertically displaced probe coupled to the tool body vertically displaced from the source probe, the vertically displaced probe adapted to be fluidly coupled to the borehole wall;

a second pressure transducer coupled to the vertically displaced probe, the second pressure transducer adapted to sense a pressure response of the formation caused by the displacing of fluid through the source probe; and

wherein the computer is adapted to determine the vertical permeability of the formation based on the pressure sensed by the first and second pressure transducers.

where ΔP_{Z }is the modeled pressure response at the vertically displaced probe, τ_{v }is a geometric shape factor for the vertically displaced probe, r_{v }is a distance between the source probe and the vertically displaced probe, k_{r }is the horizontal permeability, λ is the hydraulic permeability anisotropy, θ is the angle of the formation relative to an axis of the borehole, r_{dv }is a dimensionless distance between the source probe and the vertically displaced probe and p_{d }is a predicted transient response given substantially by the equation:

fluidly coupling a source probe to the earth formation;

fluidly coupling a vertically displaced probe to the earth formation;

measuring a pressure reaction at the source probe caused by pulling fluid from the formation into the source probe;

measuring a second pressure reaction at the vertically displaced probe caused by the pulling of fluid from the formation into the first probe;

determining the hydraulic permeability anisotropy of the earth formation with pressure reactions measured at the source and vertically displaced probes, where the determination compensates for damage to the formation near the borehole wall and the angle of the formation relative to an axis of the borehole.

where ΔP_{p }is the modeled pressure reaction the source probe, S_{d }is a dimensionless skin constant, k_{f }is the spherical permeability, μ is a formation fluid viscosity, Q_{0 }is the rate of fluid flow from the formation into the source probe, τ_{s }is a geometric shape factor for the source probe, r_{p }is the source probe radius, p_{ds }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the earth formation, t_{d }is dimensionless time, y_{n }is one of:

and where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

where ΔP_{Z }is the modeled pressure response at the vertically displaced probe, τ_{v }is a geometric shape factor for the vertically displaced probe, r_{v }is a distance between the source probe and the vertically displaced probe, k_{r }is the horizontal permeability, λ is the hydraulic permeability anisotropy, θ is the angle of the formation relative to an axis of the borehole, r_{dv }is a dimensionless distance between the source probe and the vertically displaced probe and p_{d }is a predicted transient response given substantially by the equation:

performing a draw-down test on an anisotropic earth formation traversing a borehole;

detecting pressure responses at a source probe and a vertical probe caused by the draw-down test;

determining hydraulic permeability anisotropy of the of the earth formation using the pressure responses and compensating for damage to the earth formation along a borehole wall.

where λ is the anisotropy, k_{z }is the vertical permeability, k_{r }is the horizontal permeability, τ_{s }is a geometric shape factor for the source probe, r_{v }is the radius of the vertical probe, τ_{v }is a geometric shape factor for the vertical probe, r_{s }is the radius of the source probe, ΔP_{Z }is a steady state pressure drop sensed at the vertical probe during the draw-down, ΔP_{s }is a steady state pressure drop sensed at the source probe during the draw-down test, and where S_{d }is a dimensionless constant representing the damage to the earth formation along a borehole wall determined by recursively solving substantially the following equations until a predicted pressure response matches the detected response:

where ΔP_{p}(t) is the predicted pressure response of the source probe, ΔP_{Z}(t) is the predicted pressure response of the vertical probe, k_{f }is the spherical permeability, Q_{o }is a fluid flow rate during the draw-down test, r_{p }is the radius of the source probe, μ is a formation fluid viscosity, r_{v }is a physical spacing between the source and vertical probe, r_{dv }is a dimensionless spacing between the source probe and vertical probe, p_{ds }is a predicted transient response given substantially by the equation:

where c_{d }is a dimensionless compressibility factor of fluid in the earth formation, t_{d }is dimensionless time, y_{n }is one of:

where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

and where p_{d }is given substantially by:

detecting pressure responses at a source probe and a vertical probe, each probe fluidly coupled to the earth formation, the pressure responses caused by the draw-down test; and

determining hydraulic permeability anisotropy of the of the earth formation using the pressure responses and compensating for damage to the earth formation along a borehole wall and the dip angle of the formation.

where λ is the anisotropy, k_{z }is the vertical permeability, k_{r }is the horizontal permeability, τ_{s }is a geometric shape factor for the source probe, r_{v }is a distance between the source probe the vertical probe, τ_{v }is a geometric shape factor for the vertical probe, r_{s }is a radius of the source probe, ΔP_{Z }is a pressure drop sensed at the vertical probe during the draw-down test after all the transients have dissipated, ΔP_{s }is a pressure drop sensed at the source probe during the draw-down test after all the transients have dissipated, θ is the dip angle, and where S_{d }is a dimensionless constant representing the damage to the earth formation along a borehole wall determined by recursively solving substantially the following equations until a predicted pressure response matches the detected pressure response:

where ΔP_{p}(t) is the predicted pressure response of the source probe, ΔP_{Z}(t) is the predicted pressure response of the vertical probe, k_{f }is the spherical permeability, Q_{o }is a fluid flow rate during the draw-down test, r_{p }is the radius of the source probe, μ is a formation fluid viscosity, r_{dv }is a dimensionless distance between the source probe and the vertical probe, p_{ds }is a predicted transient response given substantially by the equation:

where x_{1}, x_{2 }and x_{3 }are roots of the following equation:

and where p_{d }is given substantially by:

coupling a source probe and a vertical probe to the earth formation;

detecting formation pressure reactions associated with the draw-down test at a source probe and a vertical probe;

determining hydraulic permeability anisotropy of the earth formation using the formation pressure reactions and taking into account a dip angle of the earth formation.

where λ is the anisotropy, θ is the dip angle and where:

where τ_{s }is a geometric shape factor for the source probe, r_{v }is a distance between the source probe and the vertical probe, r_{v }is a geometric shape factor for the vertical probe, r_{s }is the equivalent source probe radius, ΔP_{Z }is a steady state pressure drop sensed at the vertical probe during the draw-down, ΔP_{s }is a steady state pressure drop sensed at the source probe during the draw-down test, p_{d}(c_{d}, t_{d}) is given substantially by:

where r_{d }is 1, c_{d }is a dimensionless compressibility factor of formation fluids, t_{d }is dimensionless time and β_{n }is one of:

and where p_{d}(r_{dv}, c_{d}, t_{d}) is given substantially by:

where r_{dv }is a dimensionless distance between the source probe and the vertical probe.

Description

- [0001]This application claims the benefit of Provisional Application Serial No. 60/325,903, which is incorporated herein by reference as if reproduced in full below.
- [0002]Not applicable.
- [0003]1. Field of the Invention
- [0004]The preferred embodiments of the present invention generally relate to determining hydraulic permeability of earth formations traversed by a borehole. More particularly, the preferred embodiments are directed to determining permeability anisotropy of the earth formations. More particularly still, the preferred embodiments are directed to determining the hydraulic permeability, permeability anisotropy and skin using an analytic model that considers the storage effect downhole, as well as the dip angle of the formation relative to the borehole.
- [0005]2. Description of the Related Art
- [0006]It is well known that some earth formations exhibit anisotropic properties. That is, certain downhole parameters may have more distinctive qualities, or may be more pronounced, in one physical direction than another. While there may be many properties that exhibit this characteristic, this specification is directed to determining the hydraulic permeability anisotropy of the earth formations.
- [0007]Permeability is a measure of how easily fluids flow through a particular environment. Earth formations having a very high permeability may flow greater volumes of liquids than formations having a low permeability for the same pressure differentials. Because of the way earth formations are formed, typically horizontal layer upon horizontal layer, the permeability of earth formations is generally higher in a direction substantially parallel to the layers of earth formation. Likewise, the permeability is generally lower in directions perpendicular to the layers of the earth formation. While it is generally true that the horizontal permeability is greater than the vertical permeability, this need not necessarily be the case.
- [0008]Permeability of a formation generally may be determined by inducing a fluid flow from the formation into a test apparatus, and measuring the pressure differential created by the induced flow. If the testing is performed with only a single probe, then the permeability determined is spherical permeability and indistinguishably contains both the horizontal and vertical permeability components. That is, using a single probe, and inducing a flow, the flow of formation fluids comes not only from locations within the formation on the same plane as the probe, but also from above and below. Thus, using only a single probe, while giving the ability to determine the permeability generally, is not sufficient to ascertain the horizontal and vertical components of the permeability. Related art devices compensate for this inability to determine both the horizontal and vertical permeability by having two probes vertically spaced apart.
- [0009]In particular, related art devices may include a source probe at a first elevation, and a second probe vertically displaced from the first probe. Further, some devices may also include a third probe at the same elevation as the first probe, but azimuthly rotated therefrom, for example, U.S. Pat. No. 5,247,830. By inducing either positive or negative pressure within the formation at the source probe (by forcing fluid flow into or out of the formation respectively), and detecting pressure response at the other probes, it is possible to determine both the horizontal and vertical components of the overall permeability of the formation. However, there are aspects of a borehole traversing an earth formation that are not determined or compensated for in devices such as those described in the U.S. Pat. No. 5,247,830.
- [0010]Drilling of earth formations typically involves a drill bit at the end of a drill string cutting or chipping away pieces of the formation. Drilling fluid, also known as “mud,” flows through an inside diameter of the drill string, through jets on the drill bit, and then back up through the annular region between the drill string and the borehole wall. The mud serves several purposes. First, the mud moving past the drill bit acts to cool and lubricate the bit. Secondly, the circulation of drilling mud through the annular region carries cuttings away from the drill bit. Finally, the drilling mud has a specific density such that the pressure within the borehole as it traverses earth formations is greater than the pressure of fluid or gas within the formations, thereby forcing the downhole hydrocarbons to remain within the formation rather than entering the borehole. If the pressure of the drilling fluid is not carefully maintained, it is possible for the downhole hydrocarbons to enter the borehole and/or expand under the reduced pressure pushing the drilling mud back toward the surface, known as “kick.”
- [0011]The rather violent process of drilling through an earth formation, in combination with the drilling mud present during the process, affects the downhole formation's ability to produce hydrocarbons. In particular, the act of drilling tends to damage, even if slightly, the formation immediately adjacent to the borehole wall. This damage may affect the permeability of the formation in this location. Further, the presence of the drilling mud at pressures greater than the formation results in invasion of the mud into the formation. This too tends to affect the permeability of the formation at locations adjacent to the borehole. While related art devices have advanced in their ability to determine both the horizontal and vertical components of the permeability in downhole formation, they are not capable of accounting for the affects of the formation damage and invasion of the drilling fluid near the borehole wall—which combination of factors is collectively known in the industry as “skin.” The effect of the skin on the measured permeability may be as high as an order of magnitude, thus contributing substantially to error in related art permeability determinations, as they do not take skin into account. Other factors too introduce error into related art determinations of permeability anisotropy, like compressibility of formation fluids and dip angle of the formation.
- [0012]With the advent of directional drilling, it is now possible, indeed probable, that any particular borehole may not be substantially vertical. That is, as the direction and inclination of the drilling process changes, the borehole may cross otherwise substantially horizontal earth formations at an angle. Thus, the axis of the borehole at any particular location may have an angle of inclination, also known as the “dip angle,” with respect to the direction of horizontal permeability. This difference in the angle between the axis of the borehole and the direction of horizontal permeability may also manifest itself where an otherwise vertical borehole crosses an earth formation itself having an inclination. Regardless of why the dip angle is present, the difference between an assumed horizontal permeability normal to the borehole axis and the actual horizontal permeability affects the determination of the actual horizontal and vertical permeability. Related art permeability testing devices do not compensate for the dip angle.
- [0013]Thus, what is needed in the art is a structure and related method for determining horizontal and vertical permeability, and thus the anisotropy of the earth formation, that takes into the account skin and dip angles of the well bore, as well as any other downhole parameter which may affect a measurement, such as the storage effect caused by compressibility of the formation fluids.
- [0014]The problems noted above are solved in large part by a formation tester comprising two probes. Collecting data regarding formation pressure starts by fluidly coupling the probes to the formation walls. At least one of the probes creates a pressure gradient which is sensed by the related probe. The pressure data obtained is then applied to a series of analytic model which take into account the skin of the formation, the dip angle encountered and the storage effects downhole.
- [0015]Using numerical regression analysis techniques, the preferred embodiments manipulate the parameters of the analytic model until the pressure response predicted by the model matches the actual pressure response. Once this is complete, the formation parameters such as permeability and skin are available in the solved model. In embodiments where one probe is used, the analytic model calculates spherical permeability taking into account one or both of the skin and dip angle. Where two probes are used, the analytic model calculates both horizontal and vertical permeability (and therefore anisotropy) taking into account one or both of skin and dip angle.
- [0016]The disclosed device and methods comprise a combination of features and advantages which enable them to overcome the deficiencies of the prior art devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.
- [0017]For a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:
- [0018][0018]FIG. 1 shows a wireline formation testing tool of the preferred embodiments;
- [0019][0019]FIG. 2A shows an internal schematic of the relevant portions of the wireline formation tool for small draw-down tests;
- [0020][0020]FIG. 2B shows an internal schematic of the relevant portions of the wireline formation tool for large draw-down tests; and
- [0021][0021]FIG. 3 shows an exemplary set of data for a small draw-down permeability test.
- [0022]Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”.
- [0023]The following table of exemplary terms is provided to aid in understanding the various parameters of the equations given below:
c = total compressibility (l/psi) c _{d }= dimensionless compressibilityk _{s }= skin permeability (md)k _{f }= formation spherical permeability (md)k _{z }= vertical permeability (md)k _{r }= horizontal permeability (md)p = pressure (psi) p _{d }= dimensionless pressureP(t) = measured pressure (psi) ΔP _{p }= source probe pressure differential (psi)ΔP _{z }= vertical probe pressure differential (psi)Q(t) = volume flow rate (cm ^{3}/s)Q _{o }= draw-down flow rate (cm^{3}/s)r = spherical coordinate (cm) r _{d }= dimensionless radiusr _{dv }= dimensionless probe spacingr _{p }= physical source radiusr _{s }= equivalent spherical source radius (cm)r _{v }= vertical probe spacing length (cm)S = skin factor S _{d }= dimensionless skin factort = time (sec) t _{d }= dimensionless timex, y, z = Cartesian coordinates (cm) μ = formation fluid viscosity (cp) φ = formation porosity λ = anisotropy (k _{z}/k_{r})τ = constant related to borehole radius τ _{s }= source probe geometric shape factorτ _{v }= vertical probe geometric shape factor - [0024]This application is directly related to the Society of Petroleum Engineers Conference Paper SPE 64650 titled “Advanced Dual Probe Formation Tester with Transient, Harmonic, and Pulsed Time-Delay Testing Methods Determines Permeability, Skin and Anisotropy,” which is incorporated herein by reference as if reproduced in full below. This application is also related to the Society of Petroleum Engineers Paper SPE 62919 titled “Advanced Permeability and Anisotropy Measurements While Testing and Sampling in Real-Time Using a Dual Probe Formation Tester,” which is also incorporated herein by reference as if reproduced in full below.
- [0025][0025]FIG. 1 shows a wireline formation tester
**10**constructed in accordance with the preferred embodiments. In particular, the wireline formation tester is preferably disposed within a borehole**12**traversing earth formations. The wireline formation tester**10**is preferably suspended by an armored multi-conductor cable**14**, which not only supports the formation tester**10**within the borehole, but also provides electrical communication pathways between the borehole**10**and a surface computer**11**. In the preferred embodiments, the surface computer**11**controls activities of the various downhole devices, and records parameters monitored during testing. The surface computer**11**also performs the modeling, described below, to determine the formation parameters in a post processing system (after the probe response are recorded). The volume between the wireline formation tester**10**and the borehole**12**may be filled with drilling fluid**16**whose specific gravity creates pressure at each depth which is greater than the formation pressure. - [0026]In order to make the permeability determinations, the wireline formation tester
**10**preferably comprises a lower or source probe**18**which may be extended from the tool**10**body to be in fluid communication with the formation, as shown in FIG. 1. Likewise, the tool**10**comprises an upper or vertical probe**20**, which is also extendable away from the tool body to be in fluid communication with the formation**12**. In order that sufficient pressure may be placed on the probes**18**,**20**to seal them against the formation wall, the wireline formation tester**10**also preferably comprises one or more stabilizers**22**placed on the opposite side of the tool body. While only one such stabilizer is shown, any number of stabilizers may be used, and their placement is not critical so long as sufficient force may be applied to the probes**18**,**20**to seal them against the formation wall. - [0027]Referring now to FIG. 2A, there is shown a schematic diagram of the relevant portions of the wireline formation tester
**10**for performing small draw-down tests. In particular, the tool**10**comprises the source probe**18**and vertical probe**20**, as discussed with respect to FIG. 1. On the ends of each of the probes**18**,**20**are seals**24**, of which one of ordinary skill in the art is fully aware, that aid in sealing of the probes**18**,**20**against the formation wall**12**. Each of the probes**18**,**20**are preferably fluidly coupled to a cylinder or chamber**26**. The chamber**26**preferably has disposed therein a piston**28**. By displacing the piston**28**within the chamber**26**, formation fluids are pulled through one or more of the probes**18**,**20**into the chamber**26**. Alternatively, each probe could have its own piston and chamber. Except for acceleration and deceleration times of the piston**28**, it is preferred that the movement of the piston, and thus the increasing volume within its respective chamber, provides a constant fluid flow rate from the formation. Referring still to FIG. 2, preferably each of the probes**18**,**20**has an associated pressure transducer, being pressure transducer**30**for the source probe**18**and transducer**32**for the vertical probe**20**. - [0028]A sequence for determining the permeability of the formation will now be described referring simultaneously to FIGS. 2A and 3. Preferably, the wireline formation tool
**10**is placed within the borehole at a particular depth level of interest. The probes**18**,**20**are extended to be in fluid communication with the formation, and likewise stabilizer**22**is extended to aid in providing sufficient force for sealing the probes**18**,**20**against the formation. Initially, valve**34**is open and thus both the source probe**18**and the vertical probe**20**are in fluid communication with the chamber**26**and piston**28**. As shown in FIG. 3, the pressure transducers**30**,**32**initially sense the hydrostatic pressure within the borehole, which in the exemplary drawing is shown by line**50**and is between 6,050 and 6,150 pounds per square inch (psi). With valve**34**open, the piston**28**is displaced within its chamber**26**causing a fluid flow from the formation through the probes**18**,**20**. Because of the permeability or resistance to flow of the formation, the pressure transducers**30**,**32**sense a pressure drop, as indicated by the terms “First Drawdown with Both Probes” in FIG. 3. After approximately five seconds, the initial flow or draw-down ceases and each of the pressure transducers**30**,**32**begin to sense formation pressure, which is lower than the hydrostatic pressure of the drilling mud within the borehole. In the exemplary drawings of FIG. 3, the formation pressure is approximately 6,000 psi. After giving the formation time to stabilize from the initial draw-down, a second flow or draw-down is performed. Prior to the second draw-down however, the valve**34**, which was open in the initial draw-down, is closed. Once the vertical probe**20**is isolated from the source probe**18**by way of valve**34**, the piston**28**is again displaced within its chamber**26**, thereby drawing fluids from the formation through the source probe**18**. The piston**28**moving downward within its chamber**26**draws fluid from the formation by creating a differential pressure between the formation and the piston. The differential pressure created is that which is necessary to move the additional volume created by the piston moving within its cylinder. Because the volume rate of flow in the second draw-down test is preferably greater than the volume rate of flow in the initial draw-down test, in one embodiment the second draw-down preferably taking approximately four cubic centimeters per second, and also because the vertical probe**20**is isolated from the piston during the second draw-down test by way of closed valve**34**, the drop in pressure sensed by pressure transducer**30**associated with the source probe**18**is typically greater than that pressure drop sensed during the initial draw-down test. The pressure sensed as a function of time by the transducer**30**is shown in the exemplary drawing of FIG. 3 in dashed lines. - [0029]Although the vertical probe
**20**is isolated during the second draw-down test, because of its relatively close spacing to the source probe, in the preferred embodiments from six to twelve inches, and because the vertical probe**20**is in fluid communication with the formation, it too senses a pressure drop which has propagated through the formation from the source probe**18**to the vertical probe**20**. The exemplary drawing of FIG. 3 shows a pressure drop sensed by the pressure transducer**32**, on the order of 9 psi, compared to a source probe sensed pressure drop of approximately 318 psi in the exemplary system. - [0030]In a second sequence for determining the permeability of the formation, pumping of fluid from the source probe
**18**during the second draw-down takes place for an extended period of time. That is, after each probe is coupled to the formation and reads formation pressure (first draw-down), the two probes are isolated from each other using valve**34**, and fluid is pumped through the source probe**18**for an extended period of time. FIG. 2B shows tool**10**for performing large or extended draw-down tests having the chamber**26**and piston**28**replaced by a pump**27**. In this arrangement, pump**27**is preferably a positive displacement pump, which could comprise a chamber and piston arrangement similar to that of FIG. 2A. In the extended pump down procedure, preferably the fluid is pumped through the source probe**18**(discharged into the borehole) at a rate of approximately one-half gallon a minute for approximately one-half hour. Thereafter, the pumping is stopped and the pressure responses sensed by the source probe**18**and the vertical prove**20**(pressure transducer**30**and**32**respectively) are monitored and recorded. For the extended pump-down test, recording times may range, depending on the formation, from ten to thirty minutes, but preferably fifteen minutes. - [0031]Determining the formation properties of interest of the preferred embodiment involves applying the waveforms representing the pressure sensed by the pressure transducers
**30**,**32**during the second draw-down test (whether the short draw-down taking only a few cubic centimeters or the extended draw-down test taking several gallons), such as those exemplified in FIG. 3, to an analytic model. In particular, the analytic model takes into account permeability of the skin, the storage effect downhole, as well as the dip angle of the formation relative to the borehole. The equation of the analytic model for the pressure response of the source probe during a draw-down test is:$\begin{array}{cc}\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{p}\ue8a0\left({r}_{p},t\right)=\left(\frac{\left(1+{S}_{d}\right)\ue89e\mu}{{k}_{f}}\ue89e\frac{{Q}_{0}}{4\ue89e\pi}\ue89e\frac{{\tau}_{s}}{{r}_{p}}\right)\ue89e\left\{\frac{{p}_{\mathrm{ds}}\ue8a0\left({c}_{d},{S}_{d},{t}_{d}\right)}{\left(1+{S}_{d}\right)}\right\}& \left(1\right)\end{array}$ - [0032]where ΔP
_{p }is the pressure response detected at the source probe**18**as a function of source probe radius r_{p }(which is related to equivalent source probe radius r,) and time t, and where S_{d }is a dimensionless skin constant, μ is the formation fluid viscosity, k_{f }is the spherical permeability, Q_{0 }is the draw-down flow rate, τ_{s }is a geometric shape factor to make corrections to the source probe radius, and p_{ds }is the source pressure transient as a function of the dimensionless compressibility factor c_{d}, the dimensionless skin S_{d }and dimensionless t_{d}. Before going on to more thoroughly define the various terms of equation (1) above, it is noted that the portion of the equation within parenthesis represents the static response of the analytic model, and the portion within the brackets represents the transient response of the analytic model. - [0033]The k
_{f }term within the denominator of the static response portion of equation (1) above is the spherical permeability. The spherical permeability is made up of both horizontal and vertical permeability components. Generally, k_{f }is defined as:$\begin{array}{cc}{k}_{f}=\sqrt[3]{{k}_{r}^{2}\ue89e{k}_{z}}& \left(2\right)\end{array}$ - [0034]where k
_{r }is the horizontal permeability, and k_{z }is the vertical permeability. The permeability k_{f}, including its horizontal and vertical components k_{r }and k_{z }respectively, are some of the unknowns to be determined using equation (1) above, as well as equation (14) with regard to the vertical probe, discussed below. The dimensionless skin factor, S_{d }is given by the equation:$\begin{array}{cc}{S}_{d}=\frac{S}{\zeta}& \left(3\right)\end{array}$ - [0035]where S is the skin factor and ζ is calculated by:
$\begin{array}{cc}\zeta =\frac{1}{\sqrt[3]{\lambda}}\ue89e\left(\frac{1}{2}+\frac{\sqrt{\lambda}\ue89e\mathrm{arc}\ue89e\text{\hspace{1em}}\ue89e\mathrm{sin}\ue89e\text{\hspace{1em}}\ue89e\left(\sqrt{1-1/\lambda}\right)}{2\ue89e\sqrt{1-1/\lambda}}\right)& \left(4\right)\end{array}$ - [0036]
- [0037]
- [0038]where δ is the skin thickness. The Q
_{o }term from equation (1) is the flow rate used in the draw-down test. In the exemplary plot shown in FIG. 3, the flow rate Q_{o }for the second draw-down used is 4 cm^{3}/s. The term τ_{s }in the static portion of equation (1) is a geometric shape factor used to make corrections to the source probe radius r_{p }that include geometric considerations in actual wireline formation testing applications. In particular, the analytic model exemplified, in part, by equation (1) above, was tested in the context of a finite element model and analysis. In that finite element model, the physical source used was a circular area projected against the side of a cylindrical borehole. The analytical solution, however, was developed assuming the physical source as a spheroid. The geometric shape factor τ_{s }thus compensates the analytical model for the difference in source geometries. Finally the geometric shape factor can be defined as - [0039]τ
_{s}=2τζ (7) - [0040]where τ is determined by the finite element model and ζ is as given above. The value of τ changes based, at least in part, on the diameter of the particular borehole. In general, τ ranges from approximately 1 for large diameter boreholes, to approximately 1.5 for small diameter boreholes, e.g. six inch diameter. Finally, with respect to the static portion of equation (1) above, the r
_{p }is related to the equivalent source radius r_{s }by the equation:$\begin{array}{cc}{r}_{s}=\frac{{r}_{p}}{{\tau}_{s}}& \left(8\right)\end{array}$ - [0041]where τ
_{s }is as defined above. - [0042]With respect to the transient portion of equation (1) above, the model equation for the pressure transient is:
$\begin{array}{cc}{p}_{\mathrm{ds}}\ue8a0\left({c}_{d},{S}_{d},{t}_{d}\right)=\frac{1+{s}_{d}}{{S}_{d}\ue89e{c}_{d}}\ue89e\sum _{n=1}^{3}\ue89e\left\{\frac{1}{{y}_{n}}\ue89e\left(1-\left(1+\frac{{x}_{n}\ue89e{S}_{d}}{1+{S}_{d}}\right)\ue89e{e}^{{x}_{n}^{2}\ue89e{t}_{d}}\ue89e\mathrm{erfc}\ue8a0\left(-{x}_{n}\ue89e\sqrt{{t}_{d}}\right)\right)\right\}& \left(9\right)\end{array}$ - [0043]where y
_{n }is one of: -
*y*_{1}*=x*_{1}(*x*_{1}*−x*_{2})(*x*_{1}*−x*_{3}) (10) -
*y*_{2}*=x*_{2}(*x*_{2}*−x*_{1})(*x*_{2}*−x*_{3}) (11) -
*y*_{3}*=x*_{3}(*x*_{3}*−x*_{1})(*x*_{3}*−x*_{2}) (12) - [0044]
- [0045]Derivation of equation (9) is provided in the appendix of Society of Petroleum Engineers Paper No. SPE 64650, which is incorporated by reference herein as if reproduced in full below, and in Society of Petroleum Engineers Paper No. SPE 62919, which is also incorporated herein by reference as if reproduced in full below.
- [0046]In similar fashion to the source probe and its related equations described above, the analytic model of the preferred embodiment is also capable of modeling the time series pressure sensed at the vertical probe
**20**. In the particular case where there is a dip angle between the formation and the well bore, and considering skin, the analytic model of the vertical probe pressure during a draw-down test is:$\begin{array}{cc}\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{z\ue89e\text{\hspace{1em}}}\ue8a0\left(z,t\right)=\left(\frac{{Q}_{0}}{4\ue89e\text{\hspace{1em}}\ue89e\pi}\ue89e\frac{{\tau}_{v}}{{r}_{v}}\ue89e\frac{\mu}{{k}_{r}}\ue89e\frac{1}{\sqrt{\lambda \ue89e\text{\hspace{1em}}\ue89e{\mathrm{sin}\ue8a0\left(\theta \right)}^{2}+{\mathrm{cos}\ue8a0\left(\theta \right)}^{2}}}\right)\ue89e\left\{{r}_{\mathrm{dv}}\ue89e{p}_{\mathrm{dv}}\ue8a0\left({r}_{\mathrm{dv}},{c}_{d},{S}_{d},{t}_{d}\right)\right\}& \left(14\right)\end{array}$ - [0047]where Q
_{0 }is the flow rate defined above, μ is the formation fluid viscosity, k_{r }is the horizontal permeability, λ is the ratio of the vertical to horizontal permeability as defined above, θ is the dip angle, and p_{d }is the dimensionless transient pressure response expected for the vertical probe as a function of the dimensionless vertical probe radius r_{dv}, the dimensionless compressibility constant c_{d}, the dimensionless skin factor S_{d }and dimensionless time t_{d}, where the dimensionless t_{d }is given by the equation:$\begin{array}{cc}{t}_{d}=\frac{t}{\phi \ue89e\text{\hspace{1em}}\ue89e{\mathrm{cr}}_{s}^{2}}\ue89e\frac{{k}_{f}}{\mu}& \left(15\right)\end{array}$ - [0048]
- [0049]where r
_{v }is the probe spacing. - [0050]Similar to the model equation of the source probe equation (14) above is logically divided into a static portion, contained in parenthesis, and a transient portion, contained in brackets. The transient portion of the analytic model representing the vertical probe response is given by:
$\begin{array}{cc}{p}_{\mathrm{dv}}\ue8a0\left({r}_{\mathrm{dv}},{c}_{d},{S}_{d},{t}_{d}\right)=\frac{1}{{S}_{d}\ue89e{r}_{\mathrm{dv}}\ue89e{c}_{d}}\ue89e\sum _{n=1}^{3}\ue89e\left\{\frac{1}{{y}_{n}}\ue89e\left(\begin{array}{c}\mathrm{erfc}\ue8a0\left(\frac{1-{r}_{\mathrm{dv}}}{2\ue89e\sqrt{{t}_{d}}}\right)-\\ {e}^{\left(-\left(1-{r}_{\mathrm{dv}}\right)\ue89e{x}_{n}+{x}_{n}^{2}\ue89e{t}_{d}\right)}\ue89e\mathrm{erfc}\ue8a0\left(\frac{1-{r}_{\mathrm{dv}}}{2\ue89e\sqrt{{t}_{d}}}-{x}_{n}\ue89e\sqrt{{t}_{d}}\right)\end{array}\right)\right\}& \left(17\right)\end{array}$ - [0051]where r
_{dv }is dimensionless probe spacing, and where the remaining parameters are as defined above. - [0052]By combining equations (1) and (14), the anisotropy for the particular formation is thus as follows:
$\begin{array}{cc}\lambda =\frac{{k}_{z}}{{k}_{r}}={\left(\frac{\left(1+{S}_{d}\right)\ue89e\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{z}}{\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{p}}\ue89e\text{\hspace{1em}}\ue89e\frac{{\tau}_{s}\ue89e{r}_{v}}{{\tau}_{v}\ue89e{r}_{s}}\ue89e\sqrt{\lambda \ue89e\text{\hspace{1em}}\ue89e{\mathrm{sin}\ue8a0\left(\theta \right)}^{2}+{\mathrm{cos}\ue8a0\left(\theta \right)}^{2}}\right)}^{3}\ue89e{\left\{\frac{{p}_{\mathrm{dv}}\ue8a0\left({c}_{d},{S}_{d},{t}_{d}\right)}{\left(1+{S}_{d}\right)\ue89e{r}_{\mathrm{dv}}\ue89e{p}_{\mathrm{dv}}\ue8a0\left({r}_{\mathrm{dv}},{c}_{d},{S}_{d},{t}_{d}\right)}\right\}}^{3}& \left(18\right)\end{array}$ - [0053]and if the dip angle is zero, this reduces to
$\begin{array}{cc}\lambda =\frac{{k}_{z}}{{k}_{r}}={\left(\frac{\left(1+{S}_{d}\right)\ue89e\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{z}}{\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{p}}\ue89e\text{\hspace{1em}}\ue89e\frac{{\tau}_{s}\ue89e{r}_{v}}{{\tau}_{v}\ue89e{r}_{s}}\right)}^{3}\ue89e{\left\{\frac{{p}_{\mathrm{dv}}\ue8a0\left({c}_{d},{S}_{d},{t}_{d}\right)}{\left(1+{S}_{d}\right)\ue89e{r}_{\mathrm{dv}}\ue89e{p}_{\mathrm{dv}}\ue8a0\left({r}_{\mathrm{dv}},{c}_{d},{S}_{d},{t}_{d}\right)}\right\}}^{3}& \left(19\right)\end{array}$ - [0054]Applying the actual sensed pressure time series to the analytic models exemplified in equations (1) and (14) will not yield the desired formation parameters information in only one calculation. That is, the variables within these equations are manipulated to make the analytic model predicted pressure response match the actual formation test data thus yielding the parameters of interest. Preferably, fluid viscosity ju is supplied by an external source, such as by MWD tools, or preferably by a viscosity analysis tool or meter coupled to the tool
**10**. An initial estimate as to the various parameters for the analytical model is made and the results predicted by the analytical model are compared to the actual time series. The parameters are accordingly adjusted, and the model run again using regression analysis techniques known to those of ordinary skill in the art. The regression analysis could take many hundreds or thousands of iterations. The regression analysis stops, in the preferred embodiments, when the modeled pressure response substantially matches the actual pressure response, within approximately five percent. The final state of the manipulated parameters when the regression analysis completes are the formation parameters determined by the model. - [0055]In embodiments having two probes, a source probe
**18**and a vertical probe**20**, the dip angle must be provided for there to be a solution to the equations. Obtaining dip angle prior to running the wireline formation testing of the preferred embodiment may be obtained by many known techniques, including measuring-while-drilling (MWD) devices capable of taking these measurements. Other parameters such as the viscosity of the formation fluid and compressibility of the formation fluid (which manifest itself as the storage effect) may be determined by other downhole tools, including the wireline formation tool itself prior to, during, or after the permeability test described herein. In yet another embodiment, only the source probe could be used, along with the analytical model of equation (**1**), and in so doing the spherical permeability, along with the skin, could be determined. - [0056]In the preferred embodiments, two probes and an externally supplied dip angle are used to determine the horizontal permeability and the permeability anisotropy. The analytic models may be manipulated, however, such that the determination as to permeability may consider only skin, or only dip angle. In the case of a permeability determination taking into consideration skin of the formation, but not dip angle, equation (1) above for the source probe would remain unchanged, but equation (14) modeling the vertical probe response reduces to:
$\begin{array}{cc}\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{Z}\ue8a0\left(t\right)=\left(\frac{{Q}_{0}}{4\ue89e\pi}\ue89e\frac{{\tau}_{v}}{{r}_{v}}\ue89e\frac{\mu}{{k}_{r}}\right)\ue89e\left\{{r}_{\mathrm{dv}}\ue89e{p}_{d}\ue8a0\left({r}_{\mathrm{dv}},{c}_{d},{S}_{d},{t}_{d}\right)\right\}& \left(20\right)\end{array}$ - [0057]with P
_{d }as defined in equation (9) above. - [0058]In the case of a permeability determination taking into dip angle but not skin, equation (
**1**) becomes:$\begin{array}{cc}\Delta \ue89e\text{\hspace{1em}}\ue89e{P}_{p}\ue8a0\left({r}_{p},t\right)=\left(\frac{{Q}_{0}\ue89e{\tau}_{s}}{4\ue89e\pi \ue89e\text{\hspace{1em}}\ue89e{r}_{p}}\ue89e\frac{\mu}{{k}_{f}}\right)\ue89e{p}_{d}\ue8a0\left({c}_{d},{t}_{d}\right)& \left(21\right)\end{array}$ - [0059]where p
_{d }is given by:$\begin{array}{cc}{p}_{d}\ue8a0\left({c}_{d},{t}_{d}\right)=\frac{1}{{r}_{d}\ue89e\sqrt{1-4\ue89e{c}_{d}}}\ue89e\sum _{n=1}^{2}\ue89e\frac{{\left(-1\right)}^{n+1}}{{\beta}_{n}}\ue8a0\left[1-{e}^{\left({\beta}_{n}^{2}\ue89e{t}_{d}\right)}\ue89e\mathrm{erfc}\ue8a0\left({\beta}_{n}\ue89e\sqrt{{t}_{d}}\right)\right]& \left(21\right)\end{array}$ - [0060]
- [0061]In this second case, taking into account dip angle but not skin, the equation for the vertical probe is the same as equation (14) above.
- [0062]Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. While the preferred embodiment is a wireline formation tester, the system and methods described in this specification could be implemented in tool within a drill string. In an drill string embodiment, drilling ceases during tested, and solving the analytic models described above takes place on a microprocessor or microprocessors within the tool. The results may be stored for later retrieval, or the results or summaries of the results telemetered to the surface using known or after developed techniques. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Patent Citations

Cited Patent | Filing date | Publication date | Applicant | Title |
---|---|---|---|---|

US2747401 * | May 13, 1952 | May 29, 1956 | Schlumberger Well Surv Corp | Methods and apparatus for determining hydraulic characteristics of formations traversed by a borehole |

US4043192 * | Jun 8, 1976 | Aug 23, 1977 | The United States Of America As Represented By The United States Energy Research And Development Administration | Apparatus for providing directional permeability measurements in subterranean earth formations |

US4742459 * | Sep 29, 1986 | May 3, 1988 | Schlumber Technology Corp. | Method and apparatus for determining hydraulic properties of formations surrounding a borehole |

US4890487 * | Apr 7, 1987 | Jan 2, 1990 | Schlumberger Technology Corporation | Method for determining horizontal and/or vertical permeability of a subsurface earth formation |

US5230244 * | Jun 28, 1990 | Jul 27, 1993 | Halliburton Logging Services, Inc. | Formation flush pump system for use in a wireline formation test tool |

US5247830 * | Sep 17, 1991 | Sep 28, 1993 | Schlumberger Technology Corporation | Method for determining hydraulic properties of formations surrounding a borehole |

US5335542 * | Feb 12, 1993 | Aug 9, 1994 | Schlumberger Technology Corporation | Integrated permeability measurement and resistivity imaging tool |

US5602334 * | Jun 17, 1994 | Feb 11, 1997 | Halliburton Company | Wireline formation testing for low permeability formations utilizing pressure transients |

US5672819 * | Mar 13, 1996 | Sep 30, 1997 | Halliburton Energy Services, Inc. | Formation evaluation using phase shift periodic pressure pulse testing |

US5703286 * | Oct 20, 1995 | Dec 30, 1997 | Halliburton Energy Services, Inc. | Method of formation testing |

US5770798 * | Feb 9, 1996 | Jun 23, 1998 | Western Atlas International, Inc. | Variable diameter probe for detecting formation damage |

US6164126 * | Oct 15, 1998 | Dec 26, 2000 | Schlumberger Technology Corporation | Earth formation pressure measurement with penetrating probe |

US6585045 * | Aug 15, 2001 | Jul 1, 2003 | Baker Hughes Incorporated | Formation testing while drilling apparatus with axially and spirally mounted ports |

US6964301 * | Jun 28, 2002 | Nov 15, 2005 | Schlumberger Technology Corporation | Method and apparatus for subsurface fluid sampling |

Referenced by

Citing Patent | Filing date | Publication date | Applicant | Title |
---|---|---|---|---|

US6986282 * | Feb 18, 2003 | Jan 17, 2006 | Schlumberger Technology Corporation | Method and apparatus for determining downhole pressures during a drilling operation |

US7011155 * | Apr 25, 2003 | Mar 14, 2006 | Baker Hughes Incorporated | Formation testing apparatus and method for optimizing draw down |

US7021405 | May 3, 2004 | Apr 4, 2006 | Halliburton Energy Services, Inc. | Determining gradients using a multi-probed formation tester |

US7024930 | Nov 15, 2004 | Apr 11, 2006 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7036579 | Nov 15, 2004 | May 2, 2006 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7117734 | Nov 15, 2004 | Oct 10, 2006 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7181960 | Aug 12, 2005 | Feb 27, 2007 | Baker Hughes Incorporated | Determination of correct horizontal and vertical permeabilities in a deviated well |

US7210344 | Nov 15, 2004 | May 1, 2007 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7224162 | Oct 1, 2004 | May 29, 2007 | Halliburton Energy Services Group, Inc. | System and methods for upscaling petrophysical data |

US7231818 | Dec 16, 2004 | Jun 19, 2007 | Baker Hughes Incorporated | Determining horizontal and vertical permeabilities by analyzing two pretests in a horizontal well |

US7263880 | May 9, 2003 | Sep 4, 2007 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7290443 | Nov 15, 2004 | Nov 6, 2007 | Schlumberger Technology Corporation | Method for measuring formation properties with a time-limited formation test |

US7448263 | Jan 22, 2007 | Nov 11, 2008 | Baker Hughes Incorporated | Practical methods to estimate horizontal and vertical permeabilities |

US7584761 * | Dec 2, 2005 | Sep 8, 2009 | Lam Research Corporation | Wafer edge surface treatment with liquid meniscus |

US7733086 | Oct 30, 2008 | Jun 8, 2010 | Halliburton Energy Services, Inc. | Systems and methods for deep-looking NMR logging |

US7755354 | Jul 13, 2010 | Halliburton Energy Services, Inc. | System and methods for T1-based logging | |

US8132621 | Nov 20, 2006 | Mar 13, 2012 | Halliburton Energy Services, Inc. | Multi-zone formation evaluation systems and methods |

US8583378 * | May 15, 2009 | Nov 12, 2013 | Total Sa | Method of estimating physical parameters of a geological formation |

US9353620 * | Mar 11, 2013 | May 31, 2016 | Schlumberger Technology Corporation | Detection of permeability anisotropy in the horizontal plane |

US9447664 | Feb 16, 2011 | Sep 20, 2016 | Halliburton Energy Services, Inc. | Multi-zone formation evaluation systems and methods |

US20040026125 * | Apr 25, 2003 | Feb 12, 2004 | Baker Hughes Incorporated | Formation testing apparatus and method for optimizing draw down |

US20040045706 * | May 9, 2003 | Mar 11, 2004 | Julian Pop | Method for measuring formation properties with a time-limited formation test |

US20040160858 * | Feb 18, 2003 | Aug 19, 2004 | Reinhart Ciglenec | Method and apparatus for determining downhole pressures during a drilling operation |

US20040230378 * | May 3, 2004 | Nov 18, 2004 | Halliburton Energy Services, Inc. | Determining gradients using a multi-probed formation tester |

US20050030021 * | Apr 30, 2004 | Feb 10, 2005 | Prammer Manfred G. | Systems and methods for NMR logging |

US20050087009 * | Nov 15, 2004 | Apr 28, 2005 | Jean-Marc Follini | Method for measuring formation properties with a time-limited formation test |

US20050098312 * | Nov 15, 2004 | May 12, 2005 | Jean-Marc Follini | Method for measuring formation properties with a time-limited formation test |

US20050116709 * | Oct 1, 2004 | Jun 2, 2005 | Proett Mark A. | System and methods for upscaling petrophysical data |

US20050173113 * | Nov 15, 2004 | Aug 11, 2005 | Jean-Marc Follini | Method for measuring formation properties with a time-limited formation test |

US20050187715 * | Nov 15, 2004 | Aug 25, 2005 | Jean-Marc Follini | Method for measuring formation properties with a time-limited formation test |

US20060042371 * | Dec 16, 2004 | Mar 2, 2006 | Baker Hughes Incorporated | Determining horizontal and vertical permeabilities by analyzing two pretests in a horizontal well |

US20060042372 * | Aug 12, 2005 | Mar 2, 2006 | Baker Hughes Incorporated | Determination of correct horizontal and vertical permeabilities in a deviated well |

US20070157719 * | Jan 22, 2007 | Jul 12, 2007 | Baker Hughes Incorporated | Practical Methods to Estimate Horizontal and Vertical Permeabilities |

US20070175273 * | Nov 15, 2004 | Aug 2, 2007 | Jean-Marc Follini | Method for measuring formation properties with a time-limited formation test |

US20070241750 * | Mar 29, 2007 | Oct 18, 2007 | Ridvan Akkurt | System and methods for T1-based logging |

US20080115934 * | Nov 20, 2006 | May 22, 2008 | Pettinato Miguel H | Multi-Zone Formation Evaluation Systems and Methods |

US20090072825 * | Oct 30, 2008 | Mar 19, 2009 | Prammer Manfred G | Systems and methods for deep-looking nmr logging |

US20090204328 * | Feb 12, 2008 | Aug 13, 2009 | Precision Energey Services, Inc. | Refined analytical model for formation parameter calculation |

US20090204329 * | Feb 12, 2008 | Aug 13, 2009 | Precision Energy Services, Inc. | Simultaneous analysis of two data sets from a formation test |

US20100121580 * | May 15, 2009 | May 13, 2010 | Total Sa | Method of estimating physical parameters of a geological formation |

US20110132601 * | Jun 9, 2011 | Halliburton Energy Services, Inc. | Multi-zone formation evaluation systems and methods | |

US20140250998 * | Mar 11, 2013 | Sep 11, 2014 | Schlumberger Technology Corporation | Detection of permeability anisotropy in the horizontal plane |

EP2120068A1 * | May 7, 2009 | Nov 18, 2009 | Total S.A. | Method for estimating the physical parameters of a geological formation |

EP3020915A1 * | Jan 5, 2012 | May 18, 2016 | Saudi Arabian Oil Company | Flow profile modeling for wells |

WO2012096826A3 * | Jan 5, 2012 | Aug 22, 2013 | Saudi Arabian Oil Company | Flow profile modeling for wells |

WO2013191693A1 * | Jun 21, 2012 | Dec 27, 2013 | Halliburton Energy Services, Inc. | Method and apparatus for formation tester data interpretation with diverse flow models |

WO2014205347A1 * | Jun 20, 2014 | Dec 24, 2014 | Schlumberger Canada Limited | Detection of permeability anisotropy in the horizontal plane with a formation testing tool |

Classifications

U.S. Classification | 73/152.05 |

International Classification | E21B49/00, E21B49/10 |

Cooperative Classification | E21B49/10, E21B49/008 |

European Classification | E21B49/00P, E21B49/10 |

Legal Events

Date | Code | Event | Description |
---|---|---|---|

Sep 25, 2002 | AS | Assignment | Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:PROETT, MARK A.;CHIN, WILSON C.;REEL/FRAME:013332/0593 Effective date: 20020924 |

Nov 20, 2009 | FPAY | Fee payment | Year of fee payment: 4 |

Nov 26, 2013 | FPAY | Fee payment | Year of fee payment: 8 |

Rotate